In a wind farm or wind power plant with a plurality of wind turbines, the first row of turbines that are reached by the unimpeded flow of air mass may extract a maximum amount of kinetic energy. However, due to this energy extraction by upstream or upwind turbines, the downstream or downwind turbines experience lower wind-speeds and turbulent wind conditions. This phenomenon, widely known as ‘wake effect’, may have an impact on an amount of electrical energy generated by downstream wind turbines as well as on fatigue load or other degradation of downstream wind turbine components.
In conventional wind farm management a wind farm controller dispatches set-points regarding active and reactive power generation to individual wind turbines without accounting for wake interactions. The local control of most variable-speed horizontal axis wind turbines under a maximum power point tracking perspective is then based on three types of mechanical actuators or wind turbine operation parameters including yaw control, blade pitch control, and generator torque control. Depending on the settings of these actuators the turbine can extract different amounts of energy, but these settings also directly influence the resulting wakes and thus the power generation at downwind turbines.
The system inertia of an electrical power system is the inherent ability to resist changes in a network frequency or grid frequency following a so called frequency event, which may be caused by a system disturbance, contingency, or other imbalance between load and production power. The system inertia is indicative of a time that lapses until the delayed change in frequency. The rotating mass of a conventional synchronous generator provides a natural inertial response that slows the rate of change in the grid frequency. Specifically, by releasing kinetic energy from the rotating masses into the system a synchronous generator directly connected to the grid and operating at the grid frequency counteracts a frequency decrease in proportion to a frequency change rate df/dt, at the expense of decreasing a rotational speed of the rotor.
Wind turbine generators may also contribute to system inertia and frequency stabilization since an appreciable amount of kinetic energy, albeit depending on available wind speed and rotor speed, is stored in the rotating blades of a wind turbine. However, most of the modern wind farms are equipped with variable-speed generators where the turbine rotor speed is decoupled from system electrical frequency through power electronics converters. Variable-speed wind turbines are equipped with voltage source converters which are either designed for the full rated power or, in the case of Doubly-Fed Induction Generators (DFIG), for about one third of the rated power. The converter may be controlled in order to adjust a generator load torque which the generator exerts on the rotor, specifically, power extraction from the rotating rotor may be increased by increasing the torque exerted by the generator acting on the rotor. While there is no natural or inherent inertial response provided from a variable-speed wind turbine, variable-speed wind turbines controlled in a specific manner may produce a fast response emulating, or mimicking, a natural inertia response. Such a controlled response to frequency changes may then be termed a ‘synthetic’ or ‘virtual’ inertial response, or kinetic energy control.
Electrical energy cannot easily be stored in large amounts within an electricity distribution network, commonly referred to as a grid, by conventional means. Therefore an amount of electrical energy fed into the grid must, at any given moment, precisely match an amount being used, i.e. being taken out of the gird, to guarantee secure operation at a given, constant frequency (e.g. 50 Hz in Europe). Unexpected fluctuations between the feed-in and take-out, or generation and consumption, of electrical energy into/out of the grid must therefore be compensated for on short time scales. This may, in particular, be achieved by rapidly increasing or reducing feed-in by suppliers, e.g. power plant operators, who for this purpose, are required to foresee reserve energy in form of a so-called control reserve, in particular an active power control reserve. This is frequently also referred to as frequency power control or (active power) grid control.
Reserve energy is required when, in a current capacity balance of a control area, a sum of an actual feed-in and/or take-out deviates from a sum of the expected capacities. Such an deviation can originate on a load side of the grid—for instance as a result of meteorological factors, and/or inaccuracy in the load forecast—or on a production side—for example due to production restrictions or stoppages, additional output from hydroelectric power plants due to heavy precipitation. Transmission system operators are therefore required to continually use control power for offseting balance capacity variations in its control area. This may technically be achieved by a three-stage regulation procedure comprising primary, secondary, and tertiary frequency control, as e.g. provided in the technical specifications of the European Network of Transmission System Operators for Electricity ENTSO-E (UCTE, which until. July 1999 was known as UCPTE (Union pour la coordination de la production et du transport de l'électricité), was incorporated into ENTSO-E on 1 Jul. 2009 and continues to exist as «Regional Group Continental Europe).
In terms of present grid operation practices, active power control for power system dynamic frequency support is divided into separate control regimes operating on various time scales. Primary Frequency Control (PFC) aims at restoring a balance between power generation and consumption on a time scale of seconds of a deviation occurring, with active power delivered e.g. being a function of a frequency deviation f-ftarget. During PFC operation, the frequency is stabilised within permissible limit values. In conventional power stations, activation takes place directly by means of turbine regulators. The network frequency is being monitored and, in case of deviations, the required primary control power needed is activated.
In addition, secondary frequency control or Automatic Generation Control (AGC) attempts at restoring the grid frequency to the scheduled value by acting on the cause of the disturbance on a time scale of minutes. Secondary control is typically activated after a few seconds, in particular after between 1 and 30 seconds, preferably between 2 and 5 seconds, and is typically completed after 10 and 30 minutes, preferably after 12-18 minutes. If the cause of the control deviation is not eliminated this time, secondary control is replaced by tertiary control. Generally secondary control power in the connected power stations is automatically actuated by a central grid controller. This requires these power stations to be in operation but not to be generating at a maximum or minimum possible nominal capacity, to be able to meet requirements of the central load frequency controller at all times.
Tertiary frequency control may be provided to disburden secondary frequency control, in particular in order to restore a sufficient reserve for secondary frequency control. The tertiary control reserve is primarily intended for adjusting major, persistent control deviations, in particular deviations occurring in connection with production outages or unexpectedly long-lasting load changes. Activation may, e.g., be triggered by electronically transmitted messages to suppliers, who are then required to adjust power plant production, typically within a time scale between 10 and 30 minutes, preferably within 12-18 minutes.
To allow for even tighter frequency control, fast control on a millisecond or sub-second time scale, which qualifies as virtual inertia, may also be applied.
For the purpose of this disclosure, dynamic frequency support continues at least until a frequency nadir is reached or until the secondary frequency control sets in. In particular, dynamic frequency support is considered to comprise both virtual inertia and primary frequency control.
Dynamic frequency support at wind turbine level may include active power reserve or prophylactic curtailment of the wind turbine output power below a maximum level and a temporary increase of the power in case of a frequency drop. Wind turbine output power curtailment comprises a deliberate reduction or de-loading of power output by some or all of the turbines within a wind farm. The power output of a variable-speed wind turbine generator may be controlled by varying the generator load torque and/or the blade pitch angles based on measurements of the generator shaft speed. Hence, curtailment includes reducing the set point of output power actively for a given wind speed and operating point, in order to allow for higher output power in response to any frequency event. Alternatively, a pitch angle of the rotor blades may be adjusted to slow down, or to accelerate or over-speed, a rotation of the rotor beyond an optimal tip speed ratio, which also reduces the power output by the wind turbine to a value below a maximum level otherwise possible for a given wind speed. The generator torque is induced by power electronics of the converter and may be actuated with negligible delay in all ranges of dynamic frequency support, while pitch motors for mechanical pitch angle adjustment may have slew-rate limits on the order of 10°/sec, hence activation of the latter is well suited for primary frequency control.
The article by I. Erlich and M. Wilch, entitled ‘Primary frequency control by wind turbines’, Proceedings of the IEEE Power and Energy Society General Meeting, Minneapolis, Minn., July 2010, proposes pitch angle control to maintain the curtailment level in order to support grid frequency in response to a frequency drop caused by an additional load. The article proposes a frequency support by utilizing kinetic energy stored in the rotating masses, to supply additional active power to the grid in case of a power imbalance. To that purpose, a carefully parametrized lead/lag compensator controller is proposed rather than a mere proportional frequency control. The article discloses the response of an inertia or kinetic energy control to a disturbance, which increases the electrical output of the wind turbine and in turn causes the rotor to decelerate on a time scale of some 10 seconds.
The U.S. Pat. No. 7,750,490 B2 proposes to increase the speed of rotation of a wind turbine rotor to above an optimum rated speed for a torque-power curve, e.g. by adjusting the pitch angle of the blades or a yaw angle of the nacelle body. Short-term over-speeding of the turbine allows to capture additional aerodynamic energy and to store the latter as inertial energy in a rotating drive train of the wind turbine. At the end of a curtailment period, the power output by the wind turbine may be increased by extracting the inertial energy stored in the drive train, by means of a frequency converter connected to a wind turbine generator and configured to control excitation of the generator to increase a torque demand on generator.
The article by Jinshik Lee et al., entitled ‘Rotor speed-based droop of a wind generator in a wind power plant for the virtual inertial control’, J Electr Eng Technol Vol. 8, page 742-749, 2013, is directed to virtual inertial energy control at wind farm level, proposing to use different droop parameters for individual wind turbines. To release more kinetic energy, the proposed algorithm has the gain of a frequency deviation loop for each DFIG wind turbine generator depend on the rotor speed of the turbine. On the other hand, the gain for the faster Rate-Of-Change-Of-Frequency ROCOF loop is set to be equal for all wind turbine generators, and in particular independent of the rotor speed. The article assumes that all wind turbine generators operate in Maximum Power Point Tracking MPPT control mode and thus have no de-loaded power, and considers wake effects via their effect on the rotor speed. Accordingly, non-uniform inertia activation in the wind farm is based on a present status of each wind turbine as determined by individual wind turbine operation optimisation.